Innovation in oilfield chemistry doesn’t happen by chance—it’s built through research, collaboration, and a deep understanding of the challenges operators face in the field. In this episode of The Water Exchange, Select Chemistry’s Senior Director of Sales Matt Smith sits down with Dr. Nicole Carrejo, Principal R&D Scientist, to explore how chemistry is shaping the next generation of oilfield performance.
From developing solid scale inhibitors and friction reducers tailored for high-TDS produced water to tackling complex compatibility issues with regional sands and wet sand logistics, the two discuss how Select’s lab-to-field approach keeps pace with rapidly evolving frac designs. Learn how their team transforms challenges into new formulations, improves efficiency, and creates chemistry built for tougher wells and better long-term production.
Full Transcript
Welcome to The Water Exchange podcast. My name is Matt Smith, senior director of sales for Select Chemistry.
I’m Nicole Correjo, principal R&D scientist at Select Chemistry.
And today, we’re gonna be talking about oil flow chemistry and the R&D that goes behind it. But before we do that, Nicole, I wanted the listeners to learn a little bit more about you and your background and how you got your start within Select.
Yeah. So I have a PhD in chemistry from Rice University. I focused on peptide synthesis and super molecular assembly, and so learned a lot about formulation and iterations of different products that way. But I found my way to Select Chemistry with a networking club that I was part of, the Association of Women in Science.
One of the individuals at Select actually posted a job through the association.
Oh, very good.
So going to school and getting my PhD in chemistry, I never anticipated working in the oil and gas industry, but it’s very prevalent here in Houston. And so when it became on my radar, I went for an interview and I was able to explain to them that my background in problem solving and learning how to fail and still learn from those failures would be translatable into this industry.
Yeah. A very similar story with me. Like, coming out of my undergrad, I didn’t know anything really about the oil and gas industry. I was fortunate enough to to start with a a large service company, they just threw me out into the field in South Texas, and that’s how I cut my teeth and really just fell in love with the industry. And then I moved into the chemistry side of things about ten years ago. And and even from, like, a business perspective, I mean, you you typically think you have to go work in finance or go work for a bank or or just sit behind a desk and look at Excel spreadsheets all day where, you know, working in in the oil and gas industry and specifically with chemistry, I mean, you’re you’re out and about and you’re you’re chasing innovation and you’re being part of a lot of solutions for customers.
Something that I didn’t think was applicable when I was first coming out, but now looking back and reflecting back, I mean, it’s it’s been a great fit.
I think the advice I would give is that just because you’re focused on research in, say, medical scenarios, that those skills you’re learning in that department or in that area of research can be transferable to other industries as well.
So talk a little bit about our lab team. I mean, how many different backgrounds do we have? There’s not a whole lot there specifically just chemistry.
I think we have two individuals that were actually trained in oil and gas for their degrees.
We have a geologist. We have two different biochemists. My background is biology and chemistry. We have individuals straight out of undergrad from chemistry and biology.
Having those different perspectives and those different backgrounds have really helped us think more outside the box and think of different solutions and being more creative.
Yeah, all of us are trained differently, and so we all tackle a project or a problem differently, and we come from it from different angles, which ends up creating a better scenario at the end. I think each day we come to work in the lab and we’re working on the same thing. We’re making friction reducers. We’re testing scale inhibitors. But no day is the same. Every problem is different at the end of the day, and we get to solve it and come up with a new recommendation for our customer.
So, Nicole, where do you spend most of your time right now in the labs? What are you focused on?
Right now, I’m working on developing solid scale inhibitor for our company.
Oh, interesting.
Yeah, so we’re doing a lot of different testing on different inhibitor chemistries and how to tailor the release rate from a solid substrate.
And so what’s the benefit of using solid scale versus the typical liquid scale?
Yeah, that’s a great question. So solid scale, we’re looking at longer term release rate rather than just an instantaneous scale inhibition with a liquid scale inhibitor.
And with the additional use of produced recycled water, scaling tendencies are continuing to increase.
Yeah, and it’s a lot of aspects that our customers are tending to look at. Before, they weren’t so interested in scale inhibitors, And we’re seeing a lot of our customers starting to care about the use of a scale inhibitor, which we’re really excited about.
And that all ties into the complete fluid package, right? And making sure all the products are being compatible with each other, and that the long term use of that fluid package is appropriate for their needs.
Correct. Yeah. We’re seeing changes from kind of an off the shelf chemistry to just a one size fit all approach to really tailoring the chemistry that’s being used for each individual well.
Right. So when I first got into the, oilfield chemistry space about ten years ago, the waters back then were a lot simpler, the frac designs were simpler, so there were a lot more off the shelf products, right, that you were able to use and they worked and it completed the job as needed.
As the industry has shifted and changed, the more produced water that’s being recycled and reused, the the harsher that the TDSs are, the harsher the iron is, more hardness within that water composition, the more challenges the chemistry is gonna face. Correct?
Yeah. Some of the scaling tendencies that we’re seeing are astronomical compared to just two, three years ago.
And not just scaling, but you’re looking at the way that the water interacts with the friction reducer, having to have a more robust product that can handle that type of water quality.
Yeah. Yeah, the compatibility of every single product that’s going downhole.
And so when you’re also looking at the friction reducer there’s kind of different designs when you’re looking at completing a well slickwater and also looking at viscosity and elasticity properties within the FR, correct?
Yeah.
So why would one look more towards viscosity and elasticity?
There’s many variables like you’re talking about.
So looking at viscosity and elasticity is important for the sand carrying capacity, right? There’s been the shift away from cross linked fluids that have that very high viscosity that can carry sand far out into formation versus the slick water that have one to two centipoise viscosity that can’t carry sand on its own and so you really need that elasticity component.
Right and the elasticity helps with carrying the proppant further into the laterals helping with the the frac width and being able to place more sand, essentially. Right?
Yeah. And not screen out.
Exactly. And and I’ve seen a trend in the past maybe twelve, eighteen months where the designs of these fracs are changing. They’re moving more and more proppant.
Yeah. More proppant and longer too. So we’re having to shift how our FRs are hydrating. Right. We want a slower hydration rather than that instantaneous hydration that everyone’s talking about initially.
So we’ve had a lot of success stories over the past couple years even since we’ve been working together.
Yeah.
And one of the instances that I always remember is that scaling issue in the Permian a couple years back where the water really caught us, I think, everyone by surprise of how hard it was. Right?
You wanna elaborate a little Yeah.
Have a little bit of PTSD from Yeah. From that one.
So when we look at traditional waters for scaling tendencies, we’re looking at maybe a one to a five on the saturation index. To put this water in perspective, it was ten thousand to fifteen thousand on the saturation index. So scale was happening instantaneous whereas normally we see it happen in kind of twenty four hours during a lab test. So we knew we had our hands full with trying to figure out what kind of product was going to work for this.
And it really became a joint effort between operations, sales, logistics on what we could really provide
And what was gonna be feasible as far as cost and protecting all of the assets for the customer. And so we went through lots of testing, lots of failures, we did literature dives and all of the things and ended up coming up to a pretty awesome scale inhibitor recommendation for the customer.
We ended up recommending it to the customer. They ended up using it and from everything that I’ve remembered everything was very successful. No issues after the fact. And I think that innovation of a newer type of chemistry specifically on the skill side also led it to future iterations that we’ve been able to commercialize and bring out to the field. The shift in the use of local sands compared to the the Northern White that was historically used, there’s been a lot of issues that came along with that, a lot of surprises that we, at least on the chemistry side, had to figure out how to handle.
Right.
So there’s a there’s a couple stories I remember. One of them being a customer in West Texas that I think they ended up using, like, six or seven different local sand mines for one job. Right? Yep. So you can imagine the the issues that potentially are happened whenever they combined them all and and you you started to use them in in the wall site.
So with the switch from Northern White to these regional sands, you start losing uniformity, you start losing specs that are very established for the Northern White sand Crush strength, different things. And so what we’re seeing is a large increase in the amount of clay that’s present in these regional sands. We see lots of fines And we even see chemicals present in the sand. And so we’re starting to treat these sands like a chemical rather than a material. And so we’ll do further chemical compatibility on the sand with all the products that we’re recommending.
Right.
And so you can see swelling because of the clay present. You can see flocculation with the fines and the FR or even the biocide that you’re using.
So we developed new testing procedures because of the issues that we’re seeing with well performance of these local sands being used and their incompatibility with FRs or different products in the in the frac fluid.
Correct.
And then also the shift from also using local sand mines dry to wet sand.
Yeah. So then you start throwing in wet sand into the scenarios and these wet sand piles are sitting on the well site and the bacteria count is climbing as they’re just baking in the sun and so we’re seeing bacteria problems because of the use of wet sand in addition to the chemical compatibility.
We’re doing kill studies in the presence and absence of sand in order to determine how much biocide is really needed.
When when you’re looking at wet sand, at least initially when it came out, there was a huge cost savings with using wet sand compared to dry sand. You’re able to still complete the wells, and I think there was a still cost savings associated with it, even with the additional chemistry that needed to be used. But ultimately, there’s other issues that come along with it logistically.
Yeah. I do know though that once they come to us for chemical recommendation, they’ve already purchased their sand, they already have their water in place and all of that components.
And so it’s easier at that point to recommend a chemical Right.
Than it is for them to go change their sand source.
Exactly.
But it’s something that we can have a conversation about for future well planning.
So what are some additional challenges that customers are bringing the lab?
We love when customers bring us problems. They don’t like when they bring us problems, but we in the lab love problems because that’s how we we learn and how we create new new products.
A lot of what we’re seeing is just this reuse of water.
We’re seeing higher TDS waters. We’re seeing harsher chemistry in the water, and we’re needing to tailor our products for that.
Right. Yeah, I’ve seen I mean we have we come across issues on a day to day basis on what’s going on in the well side whether it’s you know pressure issues on on the well sites or if you’re seeing scaling tendencies or if, you know, there’s a bacteria count that’s extremely high, if it’d be able to treat a different type of biocide. But if I were to kind of categorize it in in two different buckets on what the customers are really asking us for is is one, helping them become more efficient, and then two, increase their well performance.
I think sometimes they may have one big blanket problem, but they’re not looking at all the little things that can be happening along the way to get to that problem.
Right.
And we can start asking those questions about what’s your viscosity target?
What are all those different components that you’re not thinking about?
Right. And then the more often we have these conversations with customers, the better the relationship gets, the more they start trusting. Yeah. We’ve even had, customers come into our labs, throw on a lab coat, and do some testing alongside with you guys.
So there’s been a big shift on customers just wanting to get the job done First getting it done correctly and then the longevity of their well.
Right.
And so to handle that, we have our microfluidic machines that we’re looking at formation damage, we’re looking at conductivity, and trying to create the cleanest well possible.
Exactly. Yeah. So on the well performance side, as you mentioned, the the microfluidics that we have had that for two, three years now. Yeah.
We’ve learned so much from that technology that that nobody else has in the industry, where we’re able to really develop those newer products that are coming out to the market to tailor them so we know that they’re not causing any formation damage, and we know that the conductivity level is still high.
Right.
And then when you’re looking at the efficiency factor of what the customer is looking for, they’re really looking for how can I how can I complete more stages per day? And if I can complete more stages per day, then I can reduce my time on location by one or two days. If I can reduce my time on location by one or two days, that’s a huge cost savings.
Right.
You’re looking at the total cost that they have associated on a per day basis. So how can you do that from a chemistry perspective? Right? So, like, looking at friction reducers, if you can develop a higher performing friction reducer that can lower your well side pressures so you can increase your rate, you can increase your rate, you complete stages faster, and then you continue to go and you complete your well faster and you can save them a lot of money that way.
Right.
So I have a question. Once technology comes up with all of the testing, we finish it, we present our findings to internal, what happens at that stage?
So that’s whenever we have the presentation in front of the customer, right, where typically the r and d team is there with us. I think it’s very important to have that team there during the presentations to ask and answer any of the questions that are being asked by the customer and to fully explain the methodology behind why we tested it and and how we got the results. And then from there, if we’re successful and we’re rewarded the work, then that starts the process of making sure that everything’s manufactured properly and the quality of the product stays consistent, which I I do think there’s been a shift in that in the market over the past year or two of customers really paying attention to the quality of the product that’s arriving to location.
There’s one thing to test in the lab and to see how the performance is working from a lab perspective, but how does that translate over to the field? One of the things with select chemistry and the fact that we have our manufacturing plants in Midland, Texas and Tyler, Texas, we have a lot more control over the way that the product’s being made and the QC process that goes behind it, ensuring that the the product that is being made stays consistent and is arriving to location the way that it’s meant to be. Yeah. Have some customers that we actually we will take a sample after every single batch before it goes to location and we’ll ship it to our customer so that they can do the testing or have a third party do the testing, say on a friction reducer, to make sure that in that water quality, the every single batch is within a percent or two of each other and making sure that they’re very consistent going on location.
I know our QC parameters are very tight. We have pretty narrow lower and upper bounds and every aspect of the process is checked in different QC steps.
We call our QC techs the chemical COPs, right? They report into technology rather than into operations.
And so it’s not about just getting product out the door, it’s about getting good product out the door.
Right. They’re actually incentivized to go and find products that don’t meet QC standards.
Correct.
So in ensuring that products get to location on time, I mean, obviously, it’s extremely important because causing an EMPT because of late deliveries is just unacceptable. Right? So making sure that everything from, you know, loading the ISOs at the manufacturing plant to getting the drivers lined up a lot of times there are internal drivers, which is super beneficial, and then making sure that they’re arriving when they need to arrive.
What happens once that product gets to location?
So it depends on the customer. Right? So sometimes we have our own chem suite unit out there that’s pumping the product, or a a lot of times the it’s being pumped through the horsepower. Whenever we have our own chem unit on location, we’re able to optimize a little bit more efficiently because we have more control over what’s being pumped, we’re looking at the pressure charts, kind of partnering with the customer and looking at a stage by stage design and ensuring that, one, that the the chemical package is working and is working at the most optimized design.
That’s really cool because ultimately, that would save them money.
Right.
Customers are more educated now with looking at the chemicals being used and the costs associated with them, and then also the benefits of utilizing the chemicals in the way that they were designed to be used for. Once the job is completed, a lot of the times we’ll we’ll work together with the customer and we’ll go through and review all of the the charts stage by stage to see what’s worked and what hasn’t worked. And that way we can tailor a different design for the next one that could be even more optimized. And it’s really a data sharing exercise, which customers are are a lot more focused on looking at the data now, specifically with chemicals and and looking at the lab data and how it translate to well site performance data.
And that’s been really helpful for technology in the lab because we’re able to iterate our product and improve upon it rather than just hearing it didn’t perform.
Right. So the the closer we can give it to the customer, the more information that we can gather from them, the better direction that we can go from an R and D perspective. Yeah. Supply chain is actually really important to the way that we operate as well. A couple years ago, remember we had that that freeze where it shut down a lot of the the raw material plants?
Yeah.
And we had that monomer shortage. But we were able to adapt and maneuver in the interim until that monomer supply came back online.
Yeah, our polymer chemists were actually able to develop a whole new product within a day or two that did not require the use of that monomer. The parameters had to be set for the plant to then go make the same polymer, QC checks and things were all established, and within I think two weeks they were able to get polymer out to location.
Right, which is something that it’s it’s really hard. I don’t know if a lot of people understand that’s really hard to do and and and achieve and accomplish when you’re able to maneuver that quickly and and change the way that you’re making products in the plants from getting the raw materials needed to the the development of that product to and you can probably elaborate a little bit more on this, but when you when you develop a product in on the lab bench and then you’re having to scale it up.
Yeah. Customers are always asking how quick can you make a new product? And we say two weeks because we did it. Right?
But we don’t want to make a product in two weeks. Right. We wanna make sure that we’re doing stability checks, that we make sure that that product can freeze and unfreeze. Right?
It can withstand high temperatures and low temperatures and still give the same performance and not have issues. We send our polymer chemist to the plant and they work with the plant to make sure that that product is performing the same during the synthesis process from lab scale to plant scale.
And there are steps along that way where we have a pilot bench, you’re making a smaller reactor and you kind of step it up to the large batches.
Yeah. Definitely many steps to ensure that the biggest batch that we make has no issues.
So from an R and D perspective, when do you decide whether when you’re doing testing for a project to look at existing off the shelf, what we’ve already developed, or look at something that, you know, we have to create in something that’s brand new?
That’s a good question.
Being an r and d lab, we’re always looking for ways to create new products, to optimize a product, to improve its performance, decrease its overall cost. So there’s always components that we’re looking at. But as far as offering whole new chemistry, whole new products, it really becomes one with these this change in water chemistry. Right? We’re seeing that a lot. It’s needing to happen more often.
And we’re actually partnering with a lot of customers to create their own chemistry. They’re having interest and wanting say’s in what they’re getting.
Yeah. There’s definitely been a a a trend over the past couple years of looking at, you know, off the shelf products, and that’s been used in the field for years and years and years. And there there is a comfortability around that, right, knowing that that product’s been used in this specific formation for for a long time to to shifting to more of a customizable approach. So even a pad by pad or formation by formation approach.
Yeah. Just by changing the water chemistry, a couple thousand TDS can drastically change what products are needed.
And depending on how the formation is treating, there’s also different ways for us to evaluate it. There’s a matrix that we kind of have developed over the years of utilizing the microfluidics and tweaking the different products and and even the dosages and how they interact with each other to see what’s the most optimized fluid package for that specific scenario.
Yeah. One thing that I’ve really learned over the last few years is that more is not better.
Right.
Right? There’s instances where our customers are like, Well, I want to pump it at one GPT. We’re like, Well, you don’t need that. Right? You can drop it.
There’s point of diminishing returns.
Yeah. You can actually make the problem worse by pumping more.
Right. And then there’s also testing we can do to make sure that the doses that we’re recommending is the optimal, like the CMC on surfactants. Correct. Right?
Yeah, making sure you’re getting what you’re paying for.
Exactly. So when you’re looking at the CMC on surfactants, what’s the purpose of that test?
So the CMC is necessary to help us figure out what concentration of our surfactants to dose. We want to find out what concentration is needed to change the wet ability to go from two phase flow to one phase flow.
Right.
And that helps optimize how much oil is coming out.
Because if you go too high on the dosage there’s a point of diminishing returns. If you don’t dose enough, then you’re not getting the benefits of that.
Yeah. Too high of a dosage, you can start creating emulsion and causing other product problems, and now you need production chemicals on the hand. Right. Just add more money to the equation.
So we’ve talked about sand compatibility. We’ve talked about CMC. We’ve talked about, you know, more robust FR systems.
When you put the full fluid package together, what is the customer really truly looking for?
Ultimately, they want return for their money. Exactly. Right? They want a better well.
And so we’re seeing customers want to own their well. They want to see better performance, longevity wise. It’s all about creating more oil at the end of the day.
Right. Yeah. And and their customers are having more ownership in in the fluid side of things because they know there’s a direct impact on the chemistry that’s being used to, well productivity and, the efficiency of of their pads.
Yeah. We have many case studies that are truly showing that now.
We touched on being more efficient and helping the customer become more efficient with the well site fluids, but there’s also things outside of just what’s going on the well site that we can help being more efficient. So a lot of customers are are water constrained. They can only get so much rate to location. Yeah.
Right? And so we took that issue from a customer, and and that’s when we created the the drag reducing agent, the DRA. And that’s been extremely successful with increasing the water rate to location because you can only frac as fast as you get the water to location. Right?
And if you’d wanting to become more efficient, especially with the trend of getting more simul and trimul fracs that we’re seeing, there’s a lot more water being moved than we’ve ever seen in the past, and some of the infrastructure that’s set up can’t handle that increased water.
Right?
So they’re having to use different ideas, and that’s where the DRA came and was developed.
Yeah. So the DRA project has been a really cool one, and we’re seeing more interest in it over the last year or two.
So we have a mini loop in the lab that we’re testing different water on, where we have a team with Select Water that is monitoring and analyzing different pressure drops so we know how fast we can send it, different friction profiles we’re getting and how much improvement we’ll see.
But there’s several case studies that we talk about, right? A customer couldn’t get all their fresh water to location so they’d have to supplement with produced water.
Right.
Well now you’re mixing water and so you’re looking at scale inhibitor, you’re having to look at a different FR that can’t just be used for fresh water alone. Need something that can handle higher TDS and so it changes their whole chemical profile.
Right.
Adds to the cost of it as Yeah, adds to the cost.
And so what we’re finding is just by dosing about zero point one to zero point two GPT of a DRA, we’re able to drastically save them on the cost of chemicals, the cost of their water. And we even see improvements on the well side too.
Can you elaborate a little bit more because you mentioned the mini flow loop with the DRA and then we have our Houston Technology Center here in Houston and then we’ve also been expanding as well our lab capability. So can you elaborate a little bit more on what we’re doing and the reasons why?
So we’re expanding all of our capabilities that we have here in Houston into Midland as well. So flow loop, mini flow loop, you can do emulsion testing, we’ll have a microfluidic bench there eventually.
So that’s really exciting because the microfluidics bench, that’s we have the two here in Houston, diving into that testing and the way that we’re using those machines, the fact that we’re gonna have that capability in the Permian where we can get those results to the customers a lot quicker because we’re not having to ship samples of water and oil to Houston.
We can just go to the field in the Permian, grab them, bring them back to our lab that’s right there in Midland Right.
And jump on those testings right away.
Yeah. Yeah. Right now, we’re constrained with just shipping logistics To getting everything here to Houston and then starting testing.
Right.
And so we’ll cut off at least a day to two days with that.
Right. And then having that capabilities in the Permian with with the lab, that kind of frees up the Houston Technology Center to really focus on R and D.
Yeah. And I think it’ll allow customers to go into the lab more often, those that are centralized in the Permian And see what’s going on there. So we’ve been talking a lot about chemistry now. What do we think about for the future? What do you anticipate in one to three years?
A lot of change. Yeah. So there’s been a lot of change over the past couple years, and I expect that to continue moving forward, which is one of the reasons why I really enjoy working in this industry. There’s always something new coming out, new challenges that are coming ahead of us.
But there’s there’s been the change of of going back to being more efficient, trying to get SIML and trimmer fracks and different designs, and that just creates a lot of challenges on the water side and the chemistry side, especially when you’re having more and more produced water coming at you and we’re having to develop more robust systems for our customers to be able to to achieve their goals, right, which is to be more efficient and quicker in their operations and then also produce a better well. And when you’re looking at producing a better well, a lot of that is determined by the as well.
Right? So you’re looking at, you know, what type of chemistry is causing downhole damage or or reducing the conductivity of that, which is gonna reduce your well performance. Right? But in general, when you’re looking at the market in terms of customers’ activity, there’s there’s less and less tier one acreage that’s becoming available or that’s being used up.
So when you’re looking at going to that second tier type of acreage, you’re really gonna have to have a a much more robust chemistry package to be able to get the returns that you were seeing from that tier one acreage.
Right.
And we’re already starting to see that Right.
That shift.
Nicole, I know you’re extremely busy. There’s a lot going on in the lab right now, so I appreciate you taking the time to come and have this this talk with me. I learned a lot. I’m very passionate about chemistry and and our industry, so it it was a very enjoyable conversation.
Thank you for joining us on the Water Exchange podcast, and we’ll see you next time.
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